Natural gas is a mixture of hydrocarbons and non-hydrocarbon gases found in geologic formations beneath the earth's surface, often in association with petroleum. As obtained from the ground, raw gas contains a number of impurities which must be removed at some point. The principal impurities in natural gas are water, carbon dioxide, hydrogen sulfide, organic sulfides and condensable hydrocarbons, such as propane, butane and pentane. When idle, and particularly when the hydrocarbons are accompanied by high sulfur concentrations, hazardous sulfur compounds will accumulate at the wellbore, often at pressures significantly above atmospheric pressure. When this buildup of hazardous sulfur compounds occurs, the hazardous compounds can be released into the environment, particularly when maintenance of the well for workover or abandonment purposes is required. Furthermore, it is during such maintenance that there exists the greatest risk of injury and death to maintenance workers and the greatest risk of hazardous emissions to the environment.
Sulfur compounds, for example, hydrogen sulfide, mercaptans and sulfur oxides, such as sulfur dioxide and sulfur trioxide, can be produced by natural forces and as by-products of industrial processes. These compounds, when occurring at certain concentration levels, and, particularly, when released in the gas phase to the atmosphere, are deemed to be at least offensive and, at times, a hazard to the environment. In fact, such compounds are sometimes referred to in the art as “hazardous sulfur compounds” and they are referred to as such herein.
Generally speaking, hydrogen sulfide and organic sulfides (collectively here “sulfides”), because of their corrosiveness and toxicity, are typically removed from natural gas in the field prior to introduction to a pipeline for transport to a market or off-site processing plant. The maximum level of hydrogen sulfide, “H2S”, the primary sulfide impurity of natural gas, permitted to be introduced into a pipeline is often limited to 0.25 grains per 100 cubic feet of gas, that is, 4 parts per million (ppm), although in some instances, up to 1 grain per 100 cubic feet (16 ppm) is acceptable.
At a concentration of 700 ppm, as little as one breath of hydrogen sulfide can kill. Although hydrogen sulfide can be detected by a “rotten egg” odor in concentrations from 0.03 ppm to 150 ppm, larger concentrations paralyze a person's olfactory nerves so that odor is no longer an indicator of the hazard. With humans, small concentrations can cause coughing, nausea, severe headaches, irritation of the mucous membranes, vertigo, and loss of consciousness. Hydrogen sulfide forms explosive mixtures with air at temperatures of 260° C. or above, and is dangerously reactive with powerful oxidizing materials.
For producing wells, that is wells from which fluids are withdrawn, various methods and processes are, and have been, employed to treat hazardous sulfur compounds to prevent their release to the environment. According to some processes, such treatments are conducted at a time when the sulfur compounds are dissolved or dispersed in or otherwise intimately associated with fluid hydrocarbons after or during the removal of the fluid hydrocarbons from the well and before the fluid hydrocarbon streams are subjected to refinery operations, used as a fuel, or used as a precursor for subsequent operations. Such operations are referred to herein as “upstream” treatments. Other treatments, referred to herein as “down stream” treatments, are conducted after the fluid hydrocarbons have been refined, or used as a fuel, or employed as a precursor for the manufacture of hydrocarbon-based products.
H2S, like hydrocarbon components of natural gas, exists in the gaseous state at normal temperatures and pressures. When working on a wellbore which is known to have accumulated hazardous sulfur compounds, typically water, known as “kill water” is injected into the wellbore. Other methods include the injection of a sweetening agent such as triazine with the kill water. There are a variety of approaches for removing H2S from, or at least substantially reducing the amount of H2S in natural gas, i.e., “sweetening” natural gas. One general approach is to expose the raw natural gas to a treatment liquid containing an agent which chemically reacts with H2S, a so-called H2S scavenger. Usually, the natural gas is bubbled through the treatment liquid and as the bubbles rise through the treatment liquid, H2S comes into contact with the agent in the liquid to react and form a non-gaseous, or relatively non-volatile, product. The H2S thus becomes trapped in the liquid phase, and is thereby removed from the gas. In other schemes, a portion of a sulfur rich gas may be employed to aspirate a treatment fluid and pass the admixed stream through a mixing zone, or an atomizing nozzle before the admixture of gas and treatment fluid is contacted with the fluid in a wellbore, in a pipeline, or in a vessel. Such systems are characterized by operations which employ pumps and compressors to maintain the pressure at the wellbore during the treatment process. These treatment methods often result in incomplete scavenging of the hydrogen sulfide, with residual hydrogen sulfide concentrations of 40 to 100 ppm being typical of the gas escaping from the wellbore.
One type of agent often used to react with H2S is the reaction product of an organic amine compound having an “active hydrogen” and an aldehyde. An active hydrogen herein is a hydrogen directly bonded to a nitrogen atom. It is this type of scavenging or trapping agent to which the present invention relates. Examples of such agents are described in U.S. Pat. No. 4,978,512 (issued Dec. 18, 1990 to Dillon) and U.S. Pat. No. 5,462,721 (issued Oct. 31, 1995 to Pounds et al.). The specifications of both of these earlier patents are incorporated herein by reference.
As described by Pounds et al., there are a number of characteristics that are considered desirable in treatments containing such active agents. Generally speaking, it is desirable that the agent be highly reactive, i.e., the H2S (or organic sulfides) should react readily with the agent as the H2S passes through the treatment liquid. At the same time, it is desirable that the agent remain effective even in the presence of a large excess of CO2, that is, it should be selective. The scavenging agent should be easy to handle, that is, be of appropriate viscosity, have a suitable pour point and low toxicity. In terms of performance in the processes of the prior art, it is also desirable that the agent remain in the liquid state and not foam excessively in use to prevent contamination of the treated gas.
It was also desirable in the processes of the prior art for the reaction product(s) of the H2S and the scavenging agent to have certain characteristics. It has generally been the approach to use single phase treatments. In particular, liquid treatments in which the products of the H2S trapping reaction are soluble in the liquid have thus been considered highly desirable because of the ease of disposal of the spent fluids.
Processes are sought for mitigating wellbore emissions of hazardous sulfur compounds from closed in wells in situ where there is no flow of gas or oil from the well for a period of time during which the safe maintenance in the area above the wellbore can be conducted.
Processes are sought for intermittently mitigating high (200+ppm hydrogen sulfide) hazardous sulfur emissions at a wellbore in situ to sulfur emission levels less than about 10 ppm of hydrogen sulfide, and preferably for mitigating high sulfur levels less than about 4 ppm of hydrogen sulfide, so that maintenance personnel can work safely in the proximity of such wellbores without exposing the maintenance personnel to dangerous working conditions for discrete periods of time without requiring extensive personal safety equipment.